Substations in high and medium-voltage power networks include primary devices such as electrical cables, lines, bus bars, switches, power transformers and instrument transformers, which are generally arranged in switch yards and/or bays. These primary devices are operated in an automated way via a SA system. The SA system includes secondary devices, which can include Intelligent Electronic Devices (IED) that are responsible for protection, control and monitoring of the primary devices. The secondary devices may be assigned to hierarchical levels, such as the station level, the bay level, and the process level, where the process level is separated from the bay level by a so-called process interface. The station level of the SA system can include a supervisory computer which has an Operator Work Station (OWS) with a Human-Machine Interface (HMI) and executes a Supervisory Control And Data Acquisition (SCADA) software program, as well as a gateway that communicates the state of the substation to a Network Control Centre (NCC) and receives commands from the NCC. IEDs on the bay level, which may also be referred to as bay units or protection IEDs hereinafter, in turn are connected to each other as well as to the IEDs on the station level via an inter-bay or station bus serving the purpose of exchanging commands and status information.
Secondary devices on the process-level can include (i) sensors for voltage (VT), current (CT) and gas density measurements, (ii) contact probes for sensing switch and transformer tap changer positions, and/or (iii) actuators (I/O) for changing transformer tap positions, or for controlling switchgear like circuit breakers or disconnectors. Exemplary sensors such as non-conventional current or voltage transformers include an Analog-to-Digital (A/D) converter for sampling of analog signals, and are connected to the bay units via a dedicated or intra-bay process bus, which can be considered as the process interface replacing the conventional hard-wired process interface. The conventional hard-wired process interface connects conventional current or voltage transformers in the switchyard to the bay level equipment via dedicated copper wires, in which case the analog signals of the instrument transformers are sampled by the bay units.
A communication standard for communication between the secondary devices of a substation has been introduced by the International Electrotechnical Committee (IEC) as part of the standard IEC 61850 entitled “Communication Networks and Systems in Substations”. For non-time critical messages, IEC 61850-8-1 specifies the Manufacturing Message Specification (MMS, ISO/IEC 9506) protocol based on a reduced Open Systems Interconnection (OSI) protocol stack which is built upon the Transmission Control Protocol (TCP) and Internet Protocol (IP) in the transport and network layer, respectively, and upon Ethernet and/or RS-232C as physical media. For time-critical event-based messages, IEC 61850-8-1 specifies the Generic Object Oriented Substation Events (GOOSE) directly on the Ethernet link layer of the communication stack. For fast periodically changing signals at the process level, such as measured analog voltages or currents, IEC 61850-9-2 specifies the Sampled Value (SV) service, which, similar to GOOSE, builds directly on the Ethernet link layer. Hence, the standard defines a format to publish, as multicast messages on an industrial Ethernet, event-based messages and digitized measurement data from current or voltage sensors on the process level as a substitute to traditional copper wiring.
In short, an IED controls actuators of assigned primary devices on the basis of signals from assigned sensors for switch or tap changer position, temperature, voltage, current etc., signals from other IEDs, and signals from the supervisory system. Conversely, an IED communicates a state or behavior of its assigned primary devices (e.g., selected sensor readings) to other IEDs and/or to the supervisory system. The signals are preferably transmitted as network messages, for instance according to IEC 61850-8-1 or IEC 61850-9-2 messages as discussed above.
In a protection mode, a Protection, Control and Measurement (PCM) IED monitors the state of a substation or of a part thereof and autonomously opens an assigned circuit breaker in case the PCM IED detects a potentially dangerous situation such as an overload. In a control mode, the PCM IED executes commands from the supervisory level, such as opening and closing assigned switching elements.
In a “select before operate” sequence, an operator may reserve a switching device for operation and ask the PCM IED, by way of a switching request, to execute a particular close or open operation on a particular switch. The assigned PCM IED may then accept or refuse such a command depending on the electrical state of the attached lines in order to prevent a hazardous or damaging operation, such as connecting a live bus bar to earth. This safety mechanism is called interlocking. In IEC 61850-enabled substations, the interlocking information is transmitted over the communication network, whereas the interlocking information was previously conveyed via copper wires.
The logic implementing the interlocking can be programmed as Boolean expressions in tabular, code or function chart language on each PCM IED individually during the engineering phase of a substation project, which requires both time and considerable experience as well as a perfect knowledge of the substation topology. Parts of the interlocking logic are “compiled” and included in the function chart type logic on the PCM IEDs. This engineering process is normally done on the basis of a fixed substation topology, and requires substantial changes in case, for instance, of an extension of an existing substation.
On the other hand, when a substation is commissioned, extended or maintained, some parts of the substation may be disabled, removed, in repair or may not yet have been installed. This especially applies to substations that are built in slices, with foreseen future extensions, sometimes years later. To avoid re-engineering the interlocking logic, bridging of conventional copper wiring provides for a possibility to substitute or otherwise account for missing parts of the substation. However, bridging the wires is not possible any longer when data exchange relies on IEC 61850-like network communication, since the position of a missing or otherwise disconnected switch is not transmitted at all and is tagged as “invalid” by all recipients, thus possibly impeding operation of the recipients. Nevertheless, the position or any other status information of the missing switch can still be forced, or substituted, by a supervisory computer sending unicast MMS commands individually to each concerned IED of the SA system. This operation is manual and error-prone, and involves ensuring that all forced values are returned to real values upon re-integration of the missing substation parts. Likewise, missing bays or secondary devices do not appear in the OWS or in the gateway, but to distinguish this situation from a fault situation, the SCADA software tags these objects as “substituted” and assigns them a convenient value. Such substitutions are recorded in the substation log, but such logging cannot prevent a critical situation.
European Patent Application EP-A 1850142 is concerned with the testing of system level functionality involving several Protection, Control and Measurement (PCM) IEDs of an SA system for IEC 61850 compliant substations. An extensive testing of all conceivable control or protection functions/applications of an extended SA system, including a large number of IEDs with a multitude of configurations, is facilitated by simulating at least one of the IEDs in a testing device. Hence, only a limited number of IEDs are physically present as individual devices in a test environment, and the behavior of at least one further IED is simulated by a dedicated testing device with appropriate data processing means. The testing device sends network messages indicative of the behavior of the simulated IED according to its communication and device configuration over a substation communication network to the physically present IED to be tested. The proper working of the configured IED functions (e.g., the expected correct action as triggered by the testing device) are then verified by analyzing the device's response over its analog and digital outputs, as well as its response over the communication network.